1. Field of the Invention
This invention relates to systems and methods for measuring volume and rate of gas well flow by electrical means using differential pressure with time integration. More specifically it relates to an improved methodology for resolving measurement slippage associated with intermittent or erratic flow conditions in order to enhance accurate gas well flow measurement. In addition it relates to a method for improving gas flow control, and concomitant to that, optimum gas reservoir recovery.
2. Description of the Related Art
Because the majority of gas wells are in a decline stage, and therefore flow intermittently, the conventional mechanical chart recording and electronic flow measurement inventions are inaccurate. The gas industry acknowledges that as much as 20 percent of natural gas production is not accounted for, and therefore not paid for, because of the inadequacies of the existing measurement systems. These inadequacies are primarily due to the fact that the majority of gas wells flow intermittently, while existing flow measuring mechanical circular chart recording and electric computer systems are designed to measure continuous flow. Currently, these mistakes cannot be corrected because the existing measurement systems do not provide raw data for an audit-trail for use in recalculating possible errors due to interpretations nor do they in any other way reproduce the actual flow results. Furthermore, in both of the state-of-the-art measurement systems, the recorded data which is available can be manipulated by either the gas producers or the gas purchasers in their favor. As is further detailed below, these measurement errors and the inability to fairly and reliably audit or correct them, are the main cause of disputes between gas producers and gas purchasers. In addition, the lack of audit-trail or analytical quality gas flow trending data which could provide historical profiles of gas reservoir and gas flow performance for each well prevents the gas producer from achieving effective control and optimization of the gas well. The lack of analytical quality trending data leads to faulty gas production practices, and as a result, most gas well reservoirs are poorly managed, and fail to allow for well production optimization.
The most commonly used gas flow measurement system is the mechanical multi-pen chart recorder system. It adequately meets the gas industry's flow measurement needs for accounting purposes if the well flows at a stable, constant rate. However, this situation is rare, due for example, to intermittent gas flow, line surging, and mechanical vibration at the chart, each of which can cause a solid band of ink on the chart, thereby obscuring the actual gas flow, and resulting in gas flow measurement slippage, i.e. improperly measured gas flow. Even in the absence of those conditions, the thickness of the ink track on the chart may cause errors of as much as 30 minutes. Furthermore, because of their lack of adequate detail, and because each person who integrates a chart will do it differently, since no raw data is available, circular charts are incapable of providing a reliable audit-trail. These and other short comings make chart recorders inadequate to provide accurate gas !low data, especially for wells with erratic gas flow, plus they provide no well control options.
With the recent advancements of computer technology, electronic flow measurement (EFM) systems which are capable of frequent sampling and flow integration have begone to be used to replace the circular chart and mechanical flow integration systems. However, the on-site EFM systems introduce different problems that may result in gas flow measurement slippage. First, it must be understood that EFM systems calculate gas flow based on data generated by transducers that convert line pressure, differential pressure and the temperature of the gas flow into electrical signals of about 1 to about 5 volts. These three variables are then converted to engineering numbers and are the basic gas flow variables used to determine gas flow volume using the industry wide accepted formula of the American Gas Association (AGA-3). These basic variables which are used in EFM systems at an on-site, i.e., remote, calculating computer provide some improvement in overall accuracy and timeliness of gas flow measurement, as compared to mechanical multi-pen chart recorder systems, but they create a new set of problems in accurately measuring intermittent gas flow. These problems include the total reliance on the signal from the differential transducer to determine the flow/no-flow condition of the well for gas pressure, because 0 inches differential pressure does not necessarily mean that there is "zero" or "no gas flow" without actual knowledge or determination of actual gas flow. Without going into excessive details herein, an EFM system calculates and accumulates an hourly average flow volume so long as both the line pressure and differential pressure are positive. In addition, for the EFM system to be accurate in flow integration of erratic or intermittent flow, the transducer must be unconditionally infallible, and the gas flow in an ideal condition of no turbulence. This ideal condition does not exist in nature, because, as the gas flow rate approaches or falls below a predetermined level, say 10 inches (of water pressure) of differential pressure, the relationship between the differential pressure and the actual flow becomes erratic. At that point, these systems are not reliable because they rely on a preset moving differential pressure zero (zero cut-off) reference to establish the integration or flow period. For reasons set forth in the STELA.TM. METHODOLOGY brochure, the accuracy of the typical EFM transducer can be in error by about 0.25% because of total accuracy and transducer drift. Typically, an EFM system sets the calibration of the transducer at, say exactly 1 volt for 0 inches of differential pressure, and the transducer reading can be in error by as much as say about 0.5 inches. Since the flow calculation is reliant on a differential pressure reading to establish a flow condition, this error causes problems. As a result, the gas flow could be shut off, while the EFM system continues to compute about 50,000 cubic feet of gas per day, and conversely, the flow could actually be 50,000 cubic feet per day, yet the transducer might indicate 0 inches of differential pressure, with the result that the EFM system would calculate no flow.
Furthermore, the current, but misguided, logic says that the accuracy of the flow computing system is based on the accuracy of the EFM flow transducers which measure line pressure, differential pressure, and temperature and the frequency and speed of the calculations. However, accuracy really depends on precise awareness of the integration period, that is, knowing when true flow/no-flow conditions occur and knowing the true differential pressure based on a dynamically adjusted true zero. Currently, it is a common practice of the pipeline operator to assume that the no-flow point must be established at a certain positive differential pressure value, which incidently ensures that any slippage is in favor of the purchaser. However, the imposition of such a zero cut-off prematurely cuts off flow calculation while the well is still flowing. This is the major cause of measurement slippage in EFM systems. Under other conditions, the zero base flow could also shift positively, and without a zero cut-off, show a difference of 20%.
The EFM systems convert all engineering values of flow variables, calculate, and store hourly flow volumes at the well head location, which is usually remote from the central operations office. Typically the raw data of the basic flow parameters are discarded during integration, thereby eliminating the audit trail capability of this system. Consequently, the raw data needed for reintegration is unavailable. As a result, recalculation of the local hourly averaged data will not match the average of the integrated flow result because of the square-root effect in the flow formula of the American Gas Association (AGA-3). That is, the sum of the square-root will equal the square root of the sum only if the line pressure and differential pressure remain constant, but in nature these pressures are not (constant in most wells. This lack of audit trail requires the field personnel to enter all of the calibration factors arid all data needed for the AGA-3 flow calculation before activation of the on-site EFM systems. This information along with the transducer readings allows the on-site computer to calculate flow. The result is an average hourly flow, even if the well was only open 30 minutes, that cannot be recalculated because the raw data has not been stored. Erroneous integrated results due to incorrect entry of the above data, are found to be very difficult to correct.
Not only is unintentional human error likely with the EFM systems, but, as set forth in the STELA.TM. METHODOLOGY brochure, the possibility of intentional manipulation exists. The hourly managed data provided by the EFM system further obscures the analytical quality data needed by the producer to operate and manage the production of the well.